The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
The present disclosure relates generally to wellbore treatment and development of a reservoir and, in particular, to a system and a method for interpretation of downhole flow measurements during wellbore treatment.
Pumping treatments involving injection of acid or other types of fluids and chemicals are routinely conducted in oil and gas wells to enhance hydrocarbon production. The wells being treated often include a large section of perforated casing or open borehole that has variation in rock petrophysical properties. The most permeable layers of a treated section or interval of the formation often consume the majority of the treating fluid. As a result, the treatment fluid pumped into the well may not flow to the desired layers of the formation that need treatment. To achieve effective placement of treating fluid, the treatments often involve the use of diverting agents in the treating fluid, such as chemical or particulate material, to help reduce the flow into the more permeable layers that no longer need treatment and increase the flow into the lower permeability layers. Some examples of these treatments include acidizing treatment, hydraulic fracturing, water or gas shut-off, and scale or other types of damage removal treatments.
An alternative method to directly injecting treating fluid into the well is to conduct the treatment through a coiled tubing (CT), which can be positioned in the wellbore to place the fluid immediately adjacent to layers that need to be plugged when pumping a diverter, or adjacent to layers that need stimulation when pumping stimulation fluid. However, this technique is feasible if the operator knows beforehand which layers need to be treated by diverter and which layers need to be treated by stimulation fluid. In a well with a long perforated or open interval and highly non-uniform and unknown rock properties, which is typical of horizontal wells, knowledge of the flow distribution in the treated interval is desired for effective treatment.
Traditional flow measurement in a well is done through production logging using a flow sensor to measure the hydrocarbon production rate or injection rate in the wellbore as a function of depth. Production logging is commonly done after well stimulation treatment and is not suitable for providing immediate information for the on-site engineers to make real time adjustments in the treatment to optimize the job outcome. Production logging commonly uses spinner type flow meters which are not suitable for both chemical pumping treatments, and for CT operations, since it can be easily damaged or plugged by debris. A much more rugged and non-intrusive flow meter is needed for reliable application in CT operations. Additionally, for pumping treatment using coiled tubing, fluid can flow in either direction away from the injection ports located in a bottomhole assembly (BHA) attached to the end of the CT. Therefore, flow meters mounted both upstream and downstream of the injection ports are desired, sometimes referred to as differential flow (or DFLO) measurement tools. Detailed descriptions of such a tool are given in U.S. Patent Application Publication No. 2007/0289739, titled “Fluid Diversion Measurement Methods and Systems,” by Cooper et al. The downhole flow measurement tool measures flow velocities. The measured velocities are then translated into mean flow velocity, from which flow rate in the well at the measurement depth is obtained by multiplying the mean velocity with known wellbore cross-sectional area for a cased wellbore, or with the aid of caliper measurement in an open hole.
Once flow rates (i.e. flow velocities) are measured using the sensor technology, the measurement data is transmitted via electrical or fiber optic wires deployed in the coiled tubing, or other telemetry means, to the surface data acquisition devices for processing by computers to display the output to the engineers supervising the treatment. While the measured flow rate or velocity itself can be useful for the engineers, other quantities derived from the measured rate coupled with downhole pressure measurement would be much more informative for diagnosis of the conditions downhole, especially the flow rate into the reservoir rock at the measurement depth.
In traditional production logging, the production rate from each formation depth interval (or rate into it in the case of injection) is determined by dividing the incremental change in the measured wellbore flow rate by the incremental depth the logging tool traverses, i.e. q(z)=dQ/dz, where “q” is the flow rate of fluid into the formation per unit depth, “0” is the measured flow rate inside the wellbore, and “z” the depth. This technique is valid as long as the distribution of the flow into or out of the formation “q” does not change over the time period when logging is conducted, such as in production logging.
However, during a well treatment, especially during an acidizing treatment, the flow rate distribution into different formation layers constantly changes due to either stimulation of the formation layers to increase their flow capacity or temporary reduction in flow capacity as a result of diverting agents. Therefore, the flow rate distribution obtained from the traditional production logging can be very misleading since the flow rate into each formation layer is obtained at the time when the sensor is at that depth but may have changed when the sensor moves to a different depth. The flow rate distribution obtained this way reflects the measured rate at the sensor location as it travels in the well, rather than the actual flow rate distribution in the formation. The two are the same in the case of steady state flow (i.e. flow distribution stays constant over time), which is the case in production logging, but not in the case of typical pumping treatments where the flow profile keeps changing. Additionally, the method is also vulnerable to variations in the system parameters that may affect the measured flow rate, including pump rate fluctuation, tool rotation, and other possible causes. Therefore, modification of this technique is desirable to properly interpret the flow rate measurement during these treatments.
This disclosure proposes several methods for quantitatively characterizing a reservoir and determining the flow distribution therein from downhole flow measurements. These methods are discussed in detail below.